Oil & Gas Wells
To produce oil or gas from a reservoir, a well is drilled into a subterranean formation, which may be the reservoir or adjacent to the reservoir. Typically, a wellbore of a well must be drilled hundreds or thousands of feet into the earth to reach a hydrocarbon-bearing formation.
Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. Well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation. A well service usually involves introducing a well fluid into a well.
Drilling is the process of drilling the wellbore. After a portion of the wellbore is drilled, sections of steel pipe, referred to as casing, which are slightly smaller in diameter than the borehole, are placed in at least the uppermost portions of the wellbore. The casing provides structural integrity to the newly drilled borehole.
Cementing is a common well operation. For example, hydraulic cement compositions can be used in cementing operations in which a string of pipe, such as casing or liner, is cemented in a wellbore. The cement stabilizes the pipe in the wellbore and prevents undesirable migration of fluids along the annulus between the wellbore and the outside of the casing or liner from one zone along the wellbore to the next. Where the wellbore penetrates into a hydrocarbon-bearing zone of a subterranean formation, the casing can later be perforated to allow fluid communication between the zone and the wellbore. The cemented casing also enables subsequent or remedial separation or isolation of one or more production zones of the wellbore by using downhole tools, such as packers or plugs, or by using other techniques, such as forming sand plugs or placing cement in the perforations. Hydraulic cement compositions can also be utilized in intervention operations, such as in plugging highly permeable zones, or fractures in zones, that may be producing too much water, plugging cracks or holes in pipe strings, and the like.
Cementing and Hydraulic Cement Compositions
In a cementing operation, a hydraulic cement, water, and any other components are mixed to form a hydraulic cement composition in fluid form. The hydraulic cement composition is pumped as a fluid (typically in the form of suspension or slurry) into a desired location in the wellbore. For example, in cementing a casing or liner, the hydraulic cement composition is pumped into the annular space between the exterior surfaces of a pipe string and the borehole (that is, the wall of the wellbore). The hydraulic cement composition should be a fluid for a sufficient time before setting to allow for pumping the composition into the wellbore and for placement in a desired downhole location in the well. The cement composition is allowed time to set in the annular space, thereby forming an annular sheath of hardened, substantially impermeable cement. The hardened cement supports and positions the pipe string in the wellbore and fills the annular space between the exterior surfaces of the pipe string and the borehole of the wellbore.
It is important to maintain a cement in a pumpable slurry state until it is placed in a desired portion of the well. For this purpose, a set retarder can be used in a cement slurry, which retards the setting process and provides adequate pumping time to place the cement slurry. Alternatively or in addition, a set intensifier can be used, which accelerates the setting process. The retarder or intensifier can be used to help control the thickening time or setting of a cement composition.
Foamed Cement Slurries
Light-weight cement slurry is often used in cementing of oil wells to prevent the exertion of excess hydrostatic pressure on the subterranean formation, which otherwise could fracture the formation. Low-density materials such as hallow beads are used to design light-weight cement slurries.
However, foamed cement compositions have unique features of high compressibility and thermal insulation properties as compared to non-foamed cement compositions. Foamed cement contains gas maintained under sufficient pressure so as to prevent gas migration in the fluid during the transition of the cement slurry into a set solid mass. Also, the set foamed cement has ductile property, which is desirable for sustaining the stress.
Normally, foamed cements have been prepared using a gas and a foaming surfactant. Even though there are many foaming surfactants known in the literature, they have limitations such as reduction in compressive strength, gelation with mixing fluids (i.e., increase in slurry viscosity), incompatibility with co-additives, and poor environmental compliance. Therefore, there is a need for new surfactant that performs better over the existing materials.
Inorganic Salts in Cement Slurries
Cement slurries are often formed with water, seawater, or, for various reasons, inorganic salts such as NaCl or CaCl2 may be added. It is important that a foaming surfactant be compatible for use in a cement slurry formed with seawater or having other inorganic salts dissolved in the water. Not all foaming surfactants are compatible for use with dissolved salts.
Fluid-Loss Control
Fluids used in drilling, completion, or servicing of a wellbore can be lost to the subterranean formation while circulating the fluids in the wellbore. In particular, the fluids may enter the subterranean formation via depleted zones, zones of relatively low pressure, lost circulation zones having naturally occurring fractures, weak zones having fracture gradients exceeded by the hydrostatic pressure of the drilling fluid, and so forth. The extent of fluid losses to the formation may range from minor (for example less than 10 bbl/hr) referred to as seepage loss to severe (for example, greater than 500 bbl/hr) referred to as complete loss. As a result, the service provided by such fluid is more difficult to achieve. For example, a drilling fluid may be lost to the formation, resulting in the circulation of the fluid in the wellbore being too low to allow for further drilling of the wellbore. Also, a secondary cement or sealant composition may be lost to the formation as it is being placed in the wellbore, thereby rendering the secondary operation ineffective in maintaining isolation of the formation.
The usual approach to fluid-loss control is to substantially reduce the permeability of the matrix of the zone with a fluid-loss control material that blocks the permeability at or near the face of the rock matrix of the zone. For example, the fluid-loss control material may be a particulate that has a size selected to bridge and plug the pore throats of the matrix. All else being equal, the higher the concentration of the appropriately sized particulate, the faster bridging will occur. As the fluid phase carrying the fluid-loss control material leaks into the formation, the fluid-loss control material bridges the pore throats of the matrix of the formation and builds up on the surface of the borehole or fracture face or penetrates only a little into the matrix. The buildup of solid particulate or other fluid-loss control material on the walls of a wellbore or a fracture is referred to as a filtercake. Depending on the nature of a fluid phase and the filtercake, such a filtercake may help block the further loss of a fluid phase (referred to as a filtrate) into the subterranean formation. A fluid-loss control material is specifically designed to lower the volume of a filtrate that passes through a filter medium. Accordingly, a fluid-loss control material is sometimes referred to as a filtration control agent.